There are many practical advantages to altering at least one physical property of water, aqueous solutions, aqueous-based mixtures, and oilfield exploration and production fluids. One application of altering a physical property of such fluids is improved phase separation.
A phase is defined as a region of material in a thermodynamic system that is physically distinct, chemically uniform, and typically mechanically separable. The three common states of matter are historically known as solid, liquid and gas; with their distinction commonly based on qualitative differences in the bulk properties of the phase in which each exists. A solid phase maintains a fixed volume and shape. A liquid phase has a volume that varies only slightly but adapts to the shape of its container. A gas phase expands to occupy the volume and shape of its container.
Physical properties of a phase do not change the chemical nature of matter and are traditionally defined by classic mechanics that include, but are not limited to, area, capacitance, concentration, density, dielectric, distribution, efficacy, elasticity, electric charge, electrical conductivity, electrical impedance, electric field, electric potential, electromagnetic absorption, electromagnetic permittivity, emission, flexibility, flow rate, fluidity, frequency, hardness, inductance, intrinsic impedance, intensity, irradiation, magnetic field, magnetic flux, magnetic moment, mass, opacity, permeability, physical absorption, pressure, radiance, resistivity, reflectivity, solubility, specific heat, temperature, tension, thermal conductivity, velocity, viscosity, volume, and wave impedance. Phases may also be differentiated by solubility, the maximum amount of a solute that can dissolve in a solvent before the solute ceases to dissolve and remains in a separate phase. Water (a fluid mixture containing at least one polar substance) and oil (a non-polar liquid) can be separated into two distinct liquid phases because water has very low solubility in oil, and oil has a low solubility in water. In addition to the separation of one liquid phase from a separate and distinct liquid phase, the concept of phase separation also extends to the separation of solids from liquids, solids from vapors, and liquids from vapors.
Efficient mechanical separation and physical separation have a number of practical applications. In oilfield applications, for example, oil and natural gas (commonly referred to as “gas”) reservoirs, which also contain saltwater, are typically found in porous rock. Crude oil, petroleum liquors, gas, water, solids and other materials extracted from hydrocarbon producing formations are directed through bulk separation apparatus in order to recover marketable hydrocarbons. Oil, petroleum liquors, and/or gas containing residual amounts of water, solids and other materials are transported to processing facilities for additional processing and marketing while water, solids and other materials flowing out of a hydrocarbon producing formation are typically collected proximate a wellhead (on the surface of the Earth, on an off-shore platform, and/or on an ocean floor) for processing and/or disposal.
Hydraulic fracturing fluid, or “frac fluid”, is pumped into shale formations under high pressure to create fissures and release gas and/or oil trapped in hydrocarbon producing formations. Frac fluid is a mixture of water, chemicals, and proppants (rigid particles of substantially uniform size used to hold fractures in a hydrocarbon producing reservoir open after a hydraulic fracturing treatment). In addition to naturally occurring sand grains; man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials, are carefully sorted for size and sphericity to provide efficient flow channels to allow fluids to flow from a reservoir to a wellbore. Flowback water (a portion of the water, chemicals and proppants in frac fluid; plus water, solids phase materials, liquid phase hydrocarbons and gas phase hydrocarbons from the wellbore and producing formation) may be returned to the wellhead over a period of three to four weeks after fracturing a shale formation. At a certain point in the early life of a well, there is a transition from primarily recovering flowback water containing frac fluid to that of recovering produced water from the hydrocarbon producing formation.
Produced water is an aqueous-based mixture trapped in underground formations brought to the surface along with oil and/or gas. Produced water can also be called “brine”, “saltwater”, or “formation water.” Because this water has resided within hydrocarbon bearing formations for centuries, it typically possesses some of the chemical characteristics of the formation and the hydrocarbons produced by a formation. Produced water may include water from a hydrocarbon producing reservoir, water injected into the formation, solids phase materials from the wellbore and producing formation, and any chemicals added during drilling, production, and treatment processes. The major constituents of interest in produced water are salt content, oil and grease, organic and inorganic chemicals and naturally occurring radioactive material (NORM).
Salt content can be expressed as salinity, total dissolved solids, or electrical conductivity. The salt content in produced water varies widely, from nearly freshwater to salt levels up to ten times higher than seawater. Oil and grease refers to many types of organic chemicals that collectively lend an “organic tint” and/or “oily” property to the water. Inorganic and organic chemicals found naturally in the formation are transferred to the water through long-term contact with hydrocarbons, or are chemical additives used during drilling and operation of the well. The presence of specific chemicals and their concentration levels can vary widely. Some oil and gas formations contain small concentrations of naturally occurring radioactive material (NORM) that can be transferred into produced water. Generally, radiation levels in produced water are very low and pose no risk; however, scale from pipes and sludge from tanks holding produced water can concentrate NORM.
Produced water is the largest waste stream generated in the oil and gas exploration and production process. Over the life of a hydrocarbon producing formation, it is estimated 7-10 times more produced water than hydrocarbons can flow out of a formation. Given the volume of water and magnitude of this waste stream, the handling and disposal of produced water is a key factor in exploration and production costs; and one that must adequately protect the environment at the lowest cost to the operator.
The volume of produced water generated by oil and gas wells does not remain constant over time, and over the life of a conventional oil or gas well the water-to-oil/gas ratio increases. Water typically makes up a small percentage of produced fluids when a well initially comes on line, but over time the amount of water produced by a well tends to steadily increase and the amount of oil/gas that is recovered tends to decrease.
As used herein, water-based streams generated in oil and gas production comprising water containing at least one dissimilar material flowing from a hydrocarbon producing formation, reservoir and/or wellbore to a wellhead are referred to herein as “aqueous-based mixtures.” The term “aqueous-based mixture” refers to “oilfield production fluid containing water and at least one of crude oil, petroleum liquors, gas, solids and/or other materials extracted from hydrocarbon producing formations”, “flowback water”, “produced water”, “brine”, “formation water”, “saltwater”, as well as drilling fluids, muds, and completion fluids, and combinations thereof or equivalent water-based streams generated in oil and gas production known to those of ordinary skill in the art.
Changing the physical properties of aqueous-based mixtures is useful in separating marketable oil from water, reducing chemical usage when processing such mixtures and eliminating emulsions at oil/water interfaces in oilfield separation vessels. After the bulk separation of oil and/or gas from water, solids and other materials extracted from hydrocarbon producing formations, aqueous-based mixtures may be managed in one of several ways. Flowback water and produced water typically have high salinity along with high percentages of total suspended solids and total dissolved solids. Conventional management of these recovered fluids involves trucking aqueous-based mixtures to a wastewater disposal facility for injection into an underground formation void of viable oil and gas production. Flowback water and produced water received by disposal wells can contain 0.01%-4% free-floating and readily recoverable oil, depending on the efficiency of the bulk separation apparatus used in the field to segregate marketable oil from produced water. The cost of managing aqueous-based mixtures is a significant factor in the profitability of oil and gas production, and operators are constantly searching for cost effective means of managing water for recycling, reuse, or release into the environment.
Some aqueous-based mixtures extracted in the bulk recovery process may be injected into an oil producing formation in a secondary oil recovery technique known as “waterflooding” that may be used when an oil producing reservoir's pressure has been depleted and marketable oil production falls off due to reduced operating pressure. Waterflooding a formation, by injecting produced water back into the reservoir where it originated, typically reestablishes sufficient pressure within a hydrocarbon producing formation to allow for the recovery of additional amounts of oil.
In many instances, it may be advantageous to alter at least one physical property of an aqueous-based mixture to improve separation of water from at least one solid material and/or at least one hydrocarbon material and provide cleaner water for injection into producing formations. Further, altering at least one physical property of drilling fluids, muds, and completion fluids may be utilized to improve the separation of drill cuttings, liquid phase materials, and solid phase materials from such aqueous-based mixture. The ability to alter at least one physical property of an exploration and production fluid flowing under pressure (e.g., increasing the flow rate of water propelled at a constant pressure, or reducing the pressure required to propel a volume of water at a constant flow rate) may also increase exploration and production productivity and/or reduce costs in waterflood operations.
Altering at least one physical property of an aqueous solution may be utilized to improve blending of two or more distinct phases into a homogenous exploration and production fluid. As used herein, aqueous fluids utilized in blending two or more distinct phases into a homogenous mixture and defined by the term “aqueous solutions” refer to “water”, “aqueous-based mixtures”, “water containing at least one dissimilar material”, and combinations thereof or equivalent water-based fluids utilized in blending of two or more distinct phases into a homogenous mixture for oil and gas exploration and production known to those of ordinary skill in the art. For example, it is often desirable to blend a solid phase (e.g., bentonite) and a liquid phase (e.g., water) along with other additives to form drilling fluids used in oil and gas exploration and production that will not readily separate into distinct phases over time and/or during transportation, storage and/or use. Such “drilling mud” provides hydrostatic pressure that prevents formation fluids from entering a wellbore, keeps drill bits cool during drilling while also extracting drill cuttings from the wellbore, and/or suspends drill cuttings whenever the drilling assembly is brought in and out of the hole. Homogenous mixtures of drilling mud improve the drilling process, as well as enhance the efficiency of pumps that circulate such fluids and increase the efficiency of screens, shakers, and other apparatus downstream of the wellbore that extract drill cuttings and other contaminants from the drilling mud.
The presently claimed and/or disclosed inventive concepts have also been demonstrated to alter at least one physical property of an exploration and production fluid and affect its viscosity. As used herein, water and at least one dissimilar material propelled under pressure into a wellbore, hydrocarbon producing formation and/or reservoir may be defined by the term “exploration and production fluid” and refer to “drilling fluids”, “frac fluid”, “mud”, “drilling mud”, “completion fluid”, “acid”, “cement”, “injection well water”, “waterflood formation stimulant”, and combinations thereof or equivalent fluids utilized in oil and gas exploration and production known to those of ordinary skill in the art. An at least one dissimilar substance that may be blended with a conditioned aqueous medium to form a homogenous mixture may be selected from a group consisting of, but not limited to, at least one chemical compound and/or at least one component of an exploration and production fluid, such as “drilling fluid”, “frac fluid”, “mud”, “completion fluid”, “acid”, “cement”, “injection well water”, “waterflood formation stimulant” and combinations thereof or equivalent substances utilized in oil and gas exploration and production known to those of ordinary skill in the art.